1. Field of the Invention
Implementations of various technologies described herein generally relate to methods and systems for the acquisition, processing, and inversion of two or more sets of data signals obtained from the same subsurface area.
2. Description of the Related Art
The following descriptions and examples are not admitted to be prior art by virtue of their inclusion within this section.
Seismic data signals are typically acquired by measuring and recording data during a seismic survey. A seismic survey may be performed by repeatedly firing an impulsive seismic energy source at the surface of the earth, sea or seafloor and recording the received signals at a set of receivers. The receivers may typically be situated at the same surface as the source, but laterally displaced on regular grid positions. However, there may be situations where a non-regular distribution of the receivers is preferred or where the source and the receivers may be positioned at different depth levels. In a typical seismic survey, the source and the receivers may be displaced at fixed intervals (e.g., 25 meters) and in a certain direction (e.g., the “inline” direction). During the seismic survey, the cycle of firing the source and recording the received signals may be repeated a plurality of times. When firing the seismic source, a pressure wave may be excited and propagate into the subsurface. The pressure wave reflects off interfaces between various earth layers (such as rock, sand, shale, and chalk layers) and propagates upwardly to the set of receivers, where the particle velocity of the wave vibrations or the pressure oscillations of the wave may be measured and recorded. The strength of the reflected wave is proportional to the amount of change in elastic parameters, e.g., density, pressure velocity, and shear velocity, at the respective interfaces. Consequently, the data recorded by the receivers represents the elastic characteristics of the subsurface below the receivers. In order to arrive at volumetric images of the subsurface, the recorded signals may be processed to reduce noise and to focus and map the seismic signals to the points where the reflections occurred.
The recording of a single inline survey may commonly be referred to as a 2D seismic survey, whereas a plurality of inline or 2D surveys may commonly be referred to as a 3D seismic survey. Often, two or more 3D seismic surveys may be obtained from the same subsurface area at different times, typically with time lapses ranging from about a few months to a few years. Such surveys may commonly be referred to as time-lapse surveys. In this manner, seismic data may be acquired to monitor changes in the subsurface reservoirs caused by the production of hydrocarbons.
In a time-lapse survey when two seismic data traces are compared, two factors may change, i.e., the receptivity and the signal two-way travel time within the reservoir. When considering a seismic data set, the receptivity may be the amplitude of the seismic signal along one axis and the two-way travel time may be the time along the other axis. When analyzing the time-lapse survey, it may be desirable to discriminate between amplitude changes and two-way travel time changes or time shifts. A displacement field describing the time shift may be calculated and applied to one of the surveys.
In recent years, time-lapse seismic surveys have emerged as an important new prospecting methodology. One purpose of a time-lapse seismic survey may be to monitor changes in the seismic data signals that may be related to detectable changes in geological properties, such as fluid fill, propagation velocities, porosity, density, pressure, temperature, settlement of the overburden and the like. Analyzing these changes together with petroleum production data may assist in understanding the complex fluid mechanics of the system of migration paths, traps, and draining or sealing faults making up a hydrocarbon reservoir. Such knowledge may provide information regarding how to proceed with the exploitation of the field, such as where to place new production wells to reach bypassed pay, where to place injectors for enhanced oil recovery and the like. In the case of deciding where to place well trajectories, the situation in the reservoir overburden may become of interest as well. It may be desirable to know the in situ stress field and especially over-pressured zones to avoid well breakdowns. All this information may help produce a maximum quantity of hydrocarbons from the hydrocarbon reservoir at a minimum of cost. Accordingly, an improved method for processing time-lapse data and arriving at a better difference image may be desirable.